Mayer

Safe Production of LNG on an FPSO

Martin MayerProcess Manager, M.W.Kellogg Limited

Alan RobertsonPrincipal Safety Engineer, M.W.Kellogg Limited

John SheffieldProcess Technology Manager, M.W.Kellogg Limited

Roger CourtayNaval Architect, Chantiers de l Atlantique

Rene HarrNaval Architect, Chantiers de l Atlantique

Mayer 2

Introduction

A consortium of European companies within the Azure Project has developed the concept of

producing, storing and unloading LNG on an FPSO (Floating, Production, Storage and Off loading).

The AZURE project is a design collaboration of ship builders, process design contractors, equipment

suppliers and classification societies who are each designing and verifying part of the overall offshore

LNG chain. It s objective is to demonstrate that a fully floating LNG chain is a safe and

economically viable option.

Two hypothetical design cases have been developed for gas liquefaction:

• A stand-alone gas field located in the Australasian region with a gas liquefaction capacity of

3mtpa.

• An associated gas field located off the coast of West Africa, Gulf of Guinea with a gas liquefaction

capacity of 1mtpa.

Each design includes LNG and condensate storage, (LPG storage only for the Gulf of Guinea case), an

LNG unloading system based on the Boom To Tanker, (BTT), concept, and an accommodation

block. The processing facilities include gas reception, acid gas removal, dehydration, mercury

removal, liquefaction, fractionation, flares, utilities, and power generation facilities.

The safety analysis, layout issues, and the effect of motion on equipment in the development of the

LNG production facilities and the design of the steel hull are discussed in the following sections.

Mayer 3

Safety Analysis One of the main objectives in the design of the LNG FPSO has been to develop an overall safety

assessment to verify the feasibility of the concept from a safety point of view. This included a

hazard identification process using zonal analysis.

Zonal analysis:

• Identifies the hazards that can potentially occur on an LNG FPSO on a zone by zone basis

• Categorises them by damage and frequency according to previous safety case experience

• Reviews the hazards against specific acceptability criteria.

This simplified qualitative analysis is consistent with the current level of design carried out on the

FPSO, i.e. PFD s and layout but not P&ID s.

Hazard Identification The hazard identification process is based on typical systems associated with an LNG FPSO. This is

applicable to both the Australasia and Gulf of Guinea design cases. Those considered were riser

failure, turret failure, fire & explosion in process and liquefaction areas, storage tank hazards,

unloading operations, loss of essential utility & safety systems, blowdown and flare faults, dropped

loads, helicopter crashes and fire in accommodation block. For each system a worksheet is

completed incorporating the potential sources of accident, failure mode, triggering event, aggravating

and mitigating factors, means of detection, consequences and means to mitigate the consequences.

Frequency The frequency of each event is subjectively estimated and classified according to the categories

defined in Table 1.

Table 1

FREQUENCY AND SEVERITY DEFINITIONS

F AnnualFrequency

Return Period

1 <10-5 Extremely improbable: should not happen in recorded

history. i.e. considering several plants world-wide.

2 10-5 - 10-4 Extremely remote: should not happen in system life

3 10-4 - 10-3 Remote: not expected in the system life

E.g. At most a few percent probability

4 10-3 - 10-2 Probable: Could occur in system life

E.g. A few percent to 30% probability

5 10-2 - 10-1 Occasional: expected sometimes in the system life.

E.g. 1 to 3 times.

6 >10-1 Frequent: expected several times in the system life

E.g. More than 3 times.

Consequences

Mayer 4

The consequences and potential damage of the hazards are defined in terms of:

• Loss of life

• Asset damage/delay in production

• Environment damage

The extent of the damage/loss was categorised into five categories:

1 - negligible

2 - minor

3 - severe

4 - critical

5 - catastrophic

Acceptability Criteria

For the non-numerical zonal analysis assessment a modified version of the non-mandatory safety

acceptance criteria suggested by EN 1473 Installation & Equipment for LNG - Design of Onshore

Installations has been used. EN 1473 criteria have been used as a basis as they included

environmental as well as economic aspects.

Generally it is understood that the EN1473 acceptability criteria are too demanding compared to

existing acceptability criteria. In fact it is estimated that the EN1473 acceptability criteria are

around 100 times more demanding than criteria applied by plant operators. Therefore the criteria

adopted by this project are more relaxed than the EN1473 criteria.

Table 2 shows the initial findings of the zonal analysis. The asset damage DB is less severe than for the loss of life and environmental damage. This is

primarily because the accidents have been selected principally with an interest in loss of life. It

would also be possible to consider accidents which have a large impact on production but which do

not affect life. For example an escalating fire in which the crew evacuate.

Overall, table 2 shows that the LNG FPSO should be capable of meeting existing safety acceptability

criteria. It may be possible to meet more stringent safety criteria but this requires a level of detailed

design that has not been undertaken at this stage of the project.

Mayer 5

Table 2

First estimates of risk on acceptability matrices. 1) Loss of life:

5 *

4 ******* **

3 * ***

2 * **** ***

1 * *

1 2 3 4 5 6

Frequency

2) Asset damage/delay in Production:

5 *

4

3 ******* **

2 ** ******* **

1 * * *

1 2 3 4 5 6

Frequency

3) Fire/explosion — Environment:

5 *

4 ******* *******

3 * *

2 ** * *

1 * * *

1 2 3 4 5 6

Frequency

Acceptability Key:

Unacceptable

ALARP ( AS Low As Reasonably Practicable)

Acceptable

The symbol * denotes a single hazard event.

DB -

Co

nse

qu

ence

s D

c -

Co

nse

qu

ence

s D

A -

Co

nse

qu

ence

s

Mayer 6

Quantitative Risk Assessment A limited Quantitative Risk Assessment, (QRA), has been performed. This is based on global/high

level generic data, process hazards and immediate fatalities. An analysis of escalation and evacuation

has not been carried out.

The major objective is to provide an overall estimate of risk on the LNG FPSO. Data from this

exercise has also been used to distinguish between the different liquefaction processes on a risk basis.

Overall estimate of risk on the LNG FPSO The study is based on the standard QRA method.

Risk = Hazard Frequency x Hazard Consequence

This is based on the consequences ensuing from hydrocarbon leaks together with additional

hazards such as helicopter crash, ship collision, unloading operations, turrets/risers, dropped loads,

turbine disintegration, trips, drowning, and electrocution.

Hazard Frequency The frequency of process leaks was determined from the inventory of the process plant using typical

data for number of valves, flanges and pipe lengths from in house data for onshore LNG plants. Only

process units having a hydrocarbon inventory were selected, although some items allocated to these

process units would be in non-flammable utility services. This leads to a slightly conservative hazard

frequency. Together with these inventory values, typical failure data for LNG plants was used to

produce a table showing the frequency of process leaks for a given hole size distribution. This is

shown in Figure 1.

Figure1

02.00 x10-2

4.00 x10-2

6.00 x10-2

8.00 x10-2

1.00 x10-1

1.20 x10-1

1.40 x10-1

1.60 x10-1

0-10 10-50 50-150 150+

Hole Size (mm)

Eve

nts

/yea

r

As would be expected small holes happen often and large holes happen infrequently. However since

the consequences of the large holes are disproportionately large these comparatively rare events

cannot be ignored.

Mayer 7

For a given process leak the probability of the different outcomes does depend on the probability of

ignition. For example immediate ignition may result in a jet fire whilst delayed ignition could result

in a pool or gas cloud fire.

Frequencies of the other hazards associated with the LNG FPSO are based on high level global/generic

data.

Hazard Consequences From the hole size distribution, pressures, temperatures and compositions it is possible to model how

much material may flow out and what the consequences may be. Consequences for three process

conditions were evaluated:

• LNG spills at 4 bara.

• Mixed refrigerant leaks in order to evaluate the difference between nitrogen and hydrocarbon

liquefaction processes.

• Gas at the reception facility conditions representing the gas leaks throughout the LNG plant. As

this corresponds to the highest pressure the use of this condition should be conservative.

The physical consequences of ignition for these process conditions for representative hole sizes were

evaluated to give the following hazardous outcomes:

• Gas Cloud Fires.

• Jet Fires.

• Pool Fires.

• Explosions.

The output of the consequence modelling, in terms of the expected levels of thermal radiation and

blast overpressure, together with the expected manning levels on board the LNG FPSO, can then

be used to evaluate the potential loss of life.

Summary of Individual Risk

In the QRA only loss of life, not economic or environmental factors, was considered. The loss of

life is proportional to the number of operators exposed to the hazards, so there is a clear incentive to

minimise the manpower on the LNG FPSO. The QRA has been based on a full time manning level of

fifty personnel with additional manpower during unloading operations and non daily maintenance

activities.

The numerical safety assessment used a different acceptability criteria to the zonal analysis described

earlier in this paper. That is, the Individual Worker Risk should not exceed 10-3

fatalities per year.

A summary of the results of the overall individual worker risk on the LNG FPSO for both the

Australasia and Gulf of Guinea location is shown in Table 3. These conclude that a LNG FPSO should

be able to be built to existing safety standards and levels of acceptability.

Mayer 8

Table 3

Summary of Average Individual Risk Units are fatalities per year.

1N2 =1 mtpa LNG production with N2 liquefaction cycle.

3MR=3 mtpa LNG production with a dual mixed refrigerant liquefaction cycle

Plant Capacity & Type 1N2 3MR

Jet fire 1.54 x10-6 9.89 x10

-6

Pool fire 4.99 x10-8 2.12 x10

-8

Cloud fire 1.86 x10-6 8.66 x10

-6

Explosions 1.9 x10-6 1.18 x10

-5

SUB-TOTAL 5.36 x10-6 3.04 x10

-5

Escalation factor 3 3SUB-TOTAL Allowance for process leaks 1.61x10-5 9.12x10-5

OTHER ACCIDENTS NOT DIFFERENTIATED BY CAPACITY OR PROCESS

Helicopter Crash 2 x10-4 2 x10

-4

Ships Collision 4 x10-5 4 x10

-5

Unloading Operations 6 x10-6 6 x10

-6

Turrets/Risers 1 x10-5 1 x10

-5

Dropped Loads 1 x10-5 1 x10

-5

Turbine Disintegration 1 x10-6 1 x10

-6

Trips, Drowning, Electrocution, Other 3 x10-4 3 x10

-4

SUB-TOTAL 5.7 x10-4 5.7 x10-4

TOTAL ESTIMATE 5.86 x10-4 6.61 x10-4

Upper Limit 1 x10-3 1 x10

-3

An escalation factor of three has been used. This is a provisional figure, as a detailed analysis was not

carried out for escalation and escape. However, this figure should be achievable based on other

offshore QRA s. The low pool fire figure can be explained because the assessment of the process

does not include the product storage tanks. A fire or explosion of these storage tanks would lead to

an incident in which the LNG FPSO would not survive. The safety argument is that accidents

affecting the main storage tanks will be extremely improbable rather than that such accidents can be

withstood.

Mayer 9

Relative Risks of Refrigerant Processes Two liquefaction processes have been selected for the Azure study, a nitrogen expander cycle for the

Gulf of Guinea case, (1 MTPA associated gas), and a dual mixed refrigerant cycle for the Australasia

case, (3 MTPA gas field).

The nitrogen expander cycle was chosen as it is an inherently safer cycle than other liquefaction

processes. No refrigerant storage is required and hydrocarbon inventories within the process are

minimised. Although a less efficient process, this is less important on the overall cost for plants with

lower LNG production rates.

In the Australasia case, the liquefaction rate is much higher and the operating costs become more

prevalent. The dual mixed refrigerant cycle was chosen as it has a high efficiency yet minimises the

hydrocarbon inventories.

The risks from process leaks from using a nitrogen cycle refrigerant process to using a Mixed

Refrigerant cycle have been compared.

This comparison was made by including the fire & explosion risks of the refrigeration plant for the

Mixed Refrigerant option but excluding these for the Nitrogen Plant. Strictly speaking the nitrogen

plant may have slightly higher asphyxiation risks but these were regarded as representing risks of a

lower order of magnitude.

This approach produced the following table.

Table 4

Average Individual Risk due to Immediate deaths from Process Leaks Units are fatalities per year.

1N2 =1 mtpa LNG production with N2 liquefaction cycle.

3MR=3 mtpa LNG production with a dual mixed refrigerant liquefaction cycle

Plant Capacity & Type 1N2 1MR 3N2 3MR

Jet fire 1.54 x10-6 3.96 x10

-6 3.87 x10-6 9.89 x10

-6

Pool fire 4.99 x10-8 4.99 x10

-8 2.12 x10-8 2.12 x10

-8

Cloud fire 1.86 x10-6 3.71 x10

-6 3.52 x10-6 8.66 x10

-6

Explosions 1.9 x10-6 4.44 x10

-6 4.69 x10-6 1.18 x10

-5

TOTAL 5.36 x10-6 1.22 x10-5 1.21 x10-5 3.04 x10-5

In general the Mixed Refrigerant option increases the risks attributable to the process plant by a

factor of 2 to 3. However, this difference is small when considering the overall risks from the LNG

FPSO. Therefore overall the difference in terms of Individual Risk using the nitrogen expander cycle

rather than the DMR cycle amounts to less than 10%.

The Nitrogen cycle is a relatively inefficient process so that for a high LNG production using such a

cycle can lead to a significant loss of revenue.

If this loss of revenue is equated with the reduced loss of life then an ALARP argument could be

made, using the normal cost-benefit criteria, to determine which cycle is the preferred liquefaction

process.

Mayer 10

Overall Layout The design concept for the LNG FPSO in the Australasia location is a steel hull with an external

turret. This leads to a degree of compromise in the layout of the FPSO that is not applicable on an

onshore liquefaction plant. In general on an onshore facility, accomodation, flare systems, LNG

loading systems and process plant are kept separate to minimise the overall risk. On the FPSO this is

not possible due to the restricted space available. In addition there is the hazard associated with the

turret.

Two generic layouts are possible:

• The accommodation block located at the front, near the turret.

• The accommodation block located behind or near the unloading facilities.

The limited QRA carried out does provide some insights over where the accommodation block should

be located.

Process leaks resulting in fires and explosions 1.6x10

-2/year

Ships collisions 0.2 /year

Ignited riser leaks 4.4x10-4

/year

Ignited unloading leaks 3.1x10-4

/year

In terms of fires and explosions the risers and unloading areas have similar hazard rates. The process

area has a much higher rate so being upwind of this has significant benefits. Ship collisions, which are

mainly due to loading operations, are more likely to affect the accommodation block if it is

positioned at the stern near the unloading boom.

These numbers suggest that positioning the accommodation block at the bow near the turret is

preferred to positioning at the stern near the unloading facilities.

Positioning of process units Two factors influence the design and location of process equipment.

• The principle of placing the most hazardous systems furthest away from the accommodation

module.

• Minimising the effect of motion of key items of equipment.

The best way of evaluating which process units are the greatest risk to personnel is to conduct a QRA

which can take account of the inventory and leakage rate for each of the different units. In

particular at least two process conditions (1 liquid and 1 gas) would need be needed for each process

unit. The approach used took into account hazard rate density, fluid pressure and density, calorific

value and flammable inventories. This leads to a suggested process ordering as listed in the table 5.

Mayer 11

Table 5

SUGGESTED PROCESS UNIT ORDERING Position furthest from accommodation module Large LNG storage tanks Relatively large inventory makes these items the most risky

on the LNG FPSO. These units and associated piping must be

segregated from Process Unit risks. These tanks will be

situated below the decks so it is essential that process risks

are prevented from escalating to the main tanks and their

associated pipework.

Ethane & Propane Storage

Bullets

Large liquid inventory with heavier MW (than methane) gas.

Unloading area LNG plus regular connections and disconnections.

Refrigeration Unit

Liquid processing and some stored liquids.

Risk reduced if nitrogen cycle adopted.

Fractionation Unit Liquid processing in column bottoms heavier MW (than

methane) gas.

Condensate Stabilisation Lower pressure (25barg instead of 63-73barg for gas units)

but presence of condensate likely to make fire cases worse.

Gas receiver/reception

facilities

Highest gas pressure gives higher hazard rating than non-

LNG downstream units.

Acid Gas Removal

Mercury Removal Units

Dehydration Unit

Reducing Pressure. Predominantly gas.

Gas Turbines Some flammable gas inventory

Other Utilities Position nearest accommodation module

The actual design follows this safety recommendation except:

• The reception facility with slightly higher gas pressure is close to the accommodation.

• The process units closest to the accommodation module are the pretreatment facilities.

Since these are at least 50 m away the present view is that it is not worth disturbing the natural

process order. In fact, to adopt a layout that does not conform to the process order would entail

extra pipework which would itself increase the risk.

Mayer 12

Effect of motion A more detailed approach is required to assess the optimum location of equipment and design

guidelines that should be taken into account to ensure and maximise optimum process operation

under the prevalent sea conditions.

Basin model tests and computer simulations were carried out to define the motion characteristics of

the hull under various sea conditions. Using this data it is possible to identify the motion

characteristics of various items of equipment and hence ensure they are designed to operate

efficiently under most sea conditions, although the effect of motion on instrumentation and process

control must be considered.

Equipment on an FPSO can be categorised into the following areas, columns, separators, heat

exchangers and rotating equipment. In general equipment that is greatly affected by FPSO motions

should be located as close as possible to the centre of gravity. Less sensitive equipment can be

located further away.

Columns Packed columns have been specified, with reduced packed heights and increased number of

redistributors to reduce liquid channelling and improve performance. In the detailed design of these

units all internals will need to be carefully designed to take account into the accelerations of process

fluids due to the FPSO s motion.

Separators In general wherever possible vertical vessels have been specified to take advantage of the inherently

limited movement of the liquid interface. Large vessels, especially horizontal ones are located

physically as close as possible to the FPSO s centre of gravity so that the vertical component of the

FPSO motion is minimised.

Heat Exchangers Generally the FPSO s motion has little effect on the operations of heat exchangers.

Three different types of heat exchangers whose operation can affected by the FPSO motion are:

• Plate Fin Heat Exchanger (PFHE)

• Spiral Wound (SWHE)

• Kettle Reboilers

Plate Fin Heat Exchangers Two-phase flows feeding a PFHE should be separated into the respective phases prior to entering.

This eliminates the requirement for a 2-phase inlet distributor that is inherently difficult to operate

effectively when subjected to the FPSO s motions. The heat transfer performance of streams within

a PFHE is unlikely to be affected.

Spiral Wound Heat Exchangers These are not proven in an FPSO service. There are both mechanical integrity and process

efficiency issues to be resolved. A research programme is currently being carried out at Lehigh

University and Heriot-Watt University for Air Products to assess these issues and to recommend

design changes that will enable spiral wound exchangers to perform effectively under the conditions

expected on an FPSO.

Mayer 13

The mechanical integrity portion of the programme has been completed and shows that a SWHE can

operate satisfactorily in an FPSO environment. The analysis and methodology used to validate the

structural integrity have been certified by DNV. The process portion of the programme is still

ongoing and expected to be completed later this year.

Kettle Reboilers Kettle type reboilers behave similarly to horizontal separators. The use of internal baffles can reduce

the adverse effect of any waves generated.

In addition to baffles, the overflow weirs in reboilers need to be higher so that sufficient liquid depth

is maintained and tubes are not uncovered during motion.

Rotating equipment Pumps, compressors and expanders are generally expected to be unaffected by the FPSO s motion.

As long as the rotating equipment vendors are aware of the service location in which the equipment

is to be operated, equipment can be expected to operate efficiently and to mechanically withstand

the effects of motion.

An exception is the liquefaction compressors. These are very large machines that have a number of

stages using the same shaft. The vibration of the common shaft increases due to the motion of the

FPSO. This increased vibration of the shaft may reduce the overall efficiency of the machine and

thus affect LNG production.

In order to reduce vibration of this long single shaft it may be necessary to reduce the length and

hence have two shafts. Reducing the length of the shaft will increase the stiffness and hence reduce

the possibility of vibration occurring.

In addition to reducing the length of the shaft, more substantial supports may be required to reduce

and eliminate vibration.

Instrumentation and control The main problem with instrumentation is in the measurement of differential pressure for:

• level measurement.

• liquid-liquid interface measurement.

• density measurement.

The movement of phase boundaries between the measurement tappings disrupts all these

measurements.

To minimise these problems differential pressure (d/p) type sensors should be used in favour of float

type level sensors.

Mayer 14

Steel Hull Design

Technical requirements The design was optimised to meet the following requirements:

• LNG storage capacities large enough for several days production and export to shore terminals by

LNG carriers.

• Large deck area to accommodate liquefaction plant, flare structure, accommodation, Boom To

Tanker, (BTT), unloading system and cargo pipes.

• Limited motions under severe sea conditions for safe operation of :

� Liquefaction plant.

� Off-loading to LNG shuttle tankers.

� Partially filled cargo tanks and related sloshing aspects.

� Mooring system.

• Mooring with an external turret

Main characteristics of the steel hull Taking into account the above factors the selected design for the steel hull located in the

Australasian region with a 3 mtpa LNG production plant has the following key design parameters:

• A large size steel FPSO offering a large inertia with approximately 250 000 t displacement and

15˚m draught,

• 16,000m2 deck area to accommodate liquefaction plant, accommodation, BTT and flare,

• Twin hull offering large ballast volumes for constant draught and trim, at all LNG liquid storage

levels,

• Twin hull for safe anti-collision protection, continuous hull sections between LNG and

condensate tanks,

• Optimised hull shape and large draught for reduced sensitivity to wave excitations but still

ensuring a minimum cost,

• Forward turret mooring away from cargo area for weather vaning,

• Three large size (approximately 70 000m3 each) LNG membrane type tanks with transverse

shape and length optimised to minimise the risk of sloshing and allowing safe operation of the

tanks without filling restrictions.

Mayer 15

Sea Keeping and Model Tests The FPSO is designed to operate in Australasia in approximately 1000 m sea depth. Model tests of

the moored FPSO have been performed by MARIN (NETHERLANDS) to check motions at sea and

compatibility with the design requirements already listed. The models were constructed to a scale of

1 to 50.

The model tests have been carried out in two parts:

• LNG FPSO moored with external turret which allows weather-vaning of the vessel.

• Operational conditions with turret moored FPSO in tandem with a standard large LNG carrier.

For both parts survival and operational tests were carried out. Turret mooring stiffness was modelled

assuming the LNG carrier was connected to FPSO by a 75 meters long hawser with maximum 7730

KN breaking load.

LNG FPSO with external turret mooring

Roll Motions

Table 6 shows a summary of the maximum roll motions for the various tests, survival conditions,

wind and current in same direction, (operational collinear), wind and current perpendicular to each

other, (operational crossed), with or without a thruster in operation.

Table 6

Test no. Roll motions in degrees roll

period

Remark

Mean st.dev A max + A max - 2A max 202006 0.39 0.52 2.33 -1.32 3.65 17.5 s Survival crossed

203006 0.20 0.08 0.50 -0.10 0.49 16.5 s Operational collinear

202014 0.26 0.08 0.57 -0.06 0.51 16.6 s Operational crossed

202025 0.19 0.07 0.45 -0.06 0.32 16.8 s Operational crossed

70 kN FPSO thrust

From the table it can be concluded that the roll motions are small for the tests carried out. Maximum

roll motions are in the range of 2¡ for survival conditions and below 0.6¡ for operation of the process

plant.

The block coefficient of the FPSO is large, which means that there is a relatively large amount of

buoyancy at the bow, sides and stern of the vessel. Combined with the sharp edges between the

bottom and sides of the FPSO results in damping of the roll motion.

Mayer 16

Accelerations An important aspect of the process plant design is the accelerations due to the motion of the FPSO.

Table 7 shows the mean accelerations for the survival conditions with the wind and waves

perpendicular to the current. From the table it can be concluded that the measured accelerations are

small.

Table 7

mean St.dev A max + A max - 2A max No.

AX FPSO BL m/s2 0.01 0.11 0.30 -0.33 0.59 867

AY FPSO BL m/s2 0.00 0.11 0.35 -0.37 0.72 694

AZ FPSO BL m/s2 0.03 0.23 0.72 -0.66 1.37 835

Mooring line loads. Motions of the FPSO induce the variations of the mooring line loads. These motions consist of a

wave frequency and a low frequency part. The forces in the mooring system counteract the low

frequency motions, whereas the wave motions are only slightly reduced by the mooring system.

Figure 2 show the horizontal turret loads. Horizontal motions of the FPSO are small and hence the

resulting standard deviations of the mooring line loads are small.

Figure 2

LNG FPSO and LNG carrier in tandem During the tandem offloading test, the following points were observed:

• The system is stable without a thruster (on FPSO or LNG carrier, limited fish-tailing was observed

with a long period - above 10 minutes).

• The FPSO and LNG carriers both head to wind and waves, hence reducing roll motion for both

the FPSO and LNG carrier.

• The hawser connecting the FPSO to the LNG carrier is subject to very limited forces (about 20 %

of maximum allowable load) and hawser does not become slack during tests.

0 2000 4000 6000 8000 1.10

41.2

.10

40

1300

2600

3900

FH_TUR

kN

time

s

mean FH_TUR( ) 2201kN=

stdev FH_TUR( ) 523kN=

max FH_TUR( ) 3839kN=

min FH_TUR( ) 401kN=

Mayer 17

Figure 3 shows the force in the hawser during tandem offloading. The maximum force is observed in

the conditions where wave, wind and currents are in the same direction. The peak force, 463 kN

occurs 4350 seconds after the start of the test. This load occurs adjacent to the minimum load. The

peak load is significantly lower than the breaking load of 7730 kN for the hawser.

Figure 3

The maximum relative motions between FPSO and LNG carrier are shown in Figures 4 and 5. These

occur when the wind, waves and currents are collinear. The motions are well within the operating

limits of the Boom To Tanker loading system. As stated earlier the relative motions consist of a

wave frequency and a low frequency part. The wave frequency motions are small compared to the

low frequency motions. The low frequency motion results in the typical fish tailing motions. First

the bow of the shuttle starts to move starboard (t=2500s), when the shuttle has a small angle with

respect to the wind and current a lift force on the vessel results in a sway motion to starboard. A few

minutes later, (t=2750 s), the force on the hawser pulls the bow to portside. The lift due to wind and

current is now in the opposite direction and the shuttle sways to the port side. This can continue for

a long time and can be reduced by shortening the length of the hawser line or using the backward

stern thrust of the LNG carrier.

4000 4500 5000 5500200

0

200

400

600

Test 203006

time in seconds

H

a

w

s

e

r

f

o

r

c

Mayer 18

In summary the relative motions between the FPSO and LNG carrier show:

� Small axial displacements.

� Slow (period in excess of 10 minutes) lateral drift due to fish tailing which

can be compensated by BTT crane rotation.

� Position within operating range of boom head.

Figure 4

1510505101520

80

75

X FPSOLNGC

YFPSOLNGC

horizontal relative motions in test 203006

t = 3000 s t = 2750 s t = 3100 s

t = 2500 s

t = 2900 s

Figure 5 shows the relative motions between the FPSO and LNG carrier assuming the

FPSO is fixed. The arcs represent the possible positions of the loading boom end and the

space where loading is possible assuming the crane is in the correct position. A circle

with a diameter of 16 m represents the offloading area under the boom end.

Figure 5

7567. 56052.54537.53022. 5157. 507.51522.522. 5

15

7. 5

0

7.5

15

22.5

30

37.5

45

52.5

60

67.5

FPSO

Boom location

8m from center

b d

Boom

Offloading circular zone

under the booms end

(diameter 16 metre)

8 m offloading

iti

Mayer 19

Failure cases The following failure cases were tested:

� Bow hawser breakage during offloading.

� LNG carrier stern thrust failure.

For both cases the relative velocity between the vessels was determined. This is an

important parameter to estimate the available time to disconnect the hose line after a

bow hawser breakage. For the stern thrust failure this velocity gives an indication of the

risk of collision of the two vessels when during off loading the main thruster on the LNG

carrier fails. The test was carried out with a 30 tonne backward thrust applied to the

LNG carrier tanker.

Figure 6 shows the surge motion of the LNG carrier after the hawser failure at t=0. From

this figure it is clear that after hawser failure the LNG carrier starts to accelerate. After

approximately 50 seconds the maximum velocity is reached. The vessel drifts away with

a relative velocity of 0.38 m/s.

Figure 6

40 20 0 20 40 60 80 100110

100

90

80

X FPSOLNGC in metre

test_203008

test_203009

test_203010

time

Mayer 20

A similar test was carried out to investigate the risk of collision in calm water in case of

failure of backward thrust of LNG shuttle, due to the spring effects of both hawser and

mooring system. See Figure 7. The results of the test showed a forward speed of

0.11˚m/s for the LNG carrier. In the first 400 seconds after failure of the thruster the

LNG carrier sails forward 45 m. This figure would need to be used to determine the

period in which the BTT would need to be disconnected.

Figure 7

Test 203011, test in CALM water.LNGC with initially 370 kN stern thrust

4020080

70

60

50

40

30First 400 sec. after thrus ter failure

XFPSOLNGC Meters

YFPSOLNGC Meters

Mayer 21

Conclusions

The development work carried out for the Project Azure shows that a large steel hull FPSO can be

designed and built such that it provides sufficient topsides area for the process plant, utilities and

accommodation with and LNG storage capacity for a liquefaction capability of 3 mtpa. The steel

hull can be designed to be very stable under most sea conditions thus minimising motion on the

process equipment and the unloading operations as well as avoiding excessive impact on the LNG

storage tanks due to the effects of sloshing.

The safety assessments carried out show that the LNG FPSO should be capable of meeting existing

safety acceptability criteria.